One technique utilized in exploring a subterranean formation involves obtaining samples of formation fluid downhole. Tools such as the MDT and CHDT (trademarks of Schlumberger) are extremely useful in obtaining and analyzing such fluid samples. Tools such as the MDT (see, e.g., U.S. Pat. No. 3,859,851 to Urbanosky, and U.S. Pat. No. 4,860,581 to Zimmerman et al., which are hereby incorporated by reference in their entireties) typically include a formation interface such as fluid entry port or tubular probe cooperatively arranged with one or more wall-engaging packers, which isolate the formation interface (e.g., inlet port or sample probe) from borehole fluids and/or other contaminants. Such tools also typically include one or more sample chambers, which are coupled to the formation interface by a flowline having one or more control valves arranged therein, means for controlling a pressure drop between the formation pressure and sample chamber pressure, and various sensors such as pressure sensors, temperature sensors, and/or optical sensors to obtain information relating to the sampled fluids.
Optical sensors may be provided using, for example, an OFA, CFA or LFA (all trademarks of Schlumberger) module (see, e.g., U.S. Pat. No. 4,994,671 to Safinya et al., U.S. Pat. No. 5,266,800 to Mullins, and U.S. Pat. No. 5,939,717 to Mullins, all of which are hereby incorporated by reference in their entireties) to determine the composition of the sample fluids. The CHDT is similar in many respects to the MDT, but includes a mechanism for perforating a casing such as a drilling mechanism. An example of such a drilling mechanism may be found in “Formation Testing and Sampling through Casing,” Oilfield Review, Spring 2002, which is incorporated by reference in its entirety. However, tools such as the MDT and CHDT are typically used to obtain samples of formation oil having relatively low viscosities (e.g., typically up to 30 mPa·s). While such tools have been used to sample higher viscosity fluids, the sampling process often requires several adaptations and many hours.
As global reserves of light crude oil are diminished, the exploration of heavy oil and bitumen has become more important to maintain global supply. When evaluating heavy oil or bitumen formations, it is advantageous to obtain representative samples of the formation to determine appropriate production methods. However, due to the low mobility of heavy oil and bitumen, sampling these formations can be difficult or impossible using many known light crude oil sampling techniques.
Attempting to sample a heavy oil or bitumen, for example, without first increasing the mobility of these fluids can result in excessive drawdown pressures, which can cause failure of a pump or pumpout unit being used to extract the fluid, failure (e.g., cracking, fracturing, and/or collapse) of the formation, and/or phase changes and, thus, compositional changes to the fluid being sampled. Further, such excessive drawdown pressures can lead to the production of sand, which may cause failure of sampling tool seals. While increasing the areas of the sampling ports or probes can reduce the drawdown pressures somewhat, larger port or probe areas can be difficult to achieve without adversely impacting overall size of the sampling tool and the ability to achieve an effective seal around the sampling ports or probes.
One factor contributing to the low mobility of heavy oil and bitumen formations is the high viscosity of these fluids. Therefore, substantially reducing the viscosity of the heavy oil and bitumen in the formations can help increase mobility sufficiently to obtain a sample. Some known methods to increase the mobility of formation fluid involve heating the formation through a variety of means, injecting a diluent into the formation, or injecting a solvent into the formation.
Heating a formation has typically been accomplished by thermal conduction using a heating element, in situ combustion of some of the oil in the formation, circulation of hot steam into the formation. However, these known methods rely primarily on the thermal conduction of the formation and, thus, the volume of the formation that must be heated is often much greater than the volume being sampled, leading to long sampling times and a greater probability of the sampling tool becoming trapped in the wellbore.